1. Technical Field of the Invention
The present invention generally relates to methods of desulfurizing H2S-containing gas streams. More particularly, the present invention relates to sulfur recovery processes employing the catalyzed direct partial oxidation of H2S to elemental sulfur and water and to catalyst compositions that are active for catalyzing that process.
2. Description of the Related Art
Hydrocarbon gases that occur as natural formations in the ground (“natural gas”) typically contain a mixture of gaseous hydrocarbons, chiefly methane and some C2-C4 alkanes, and often includes up to 25% hydrogen sulfide. The hydrogen sulfide content is problematic. Not only does it have an intensely unpleasant odor, it is also toxic and constitutes an unwanted component in the end products produced from the natural gas. Governmental regulations restrict the amount of H2S that can be introduced into the environment to only a few parts per million. Because it is more economical to transport natural gas in the form of a liquid rather than as a gas, most natural gas production operations include converting the natural gas to liquefied petroleum gas (LPG) at the well site. A drawback of working with the H2S-containing LPG is that the H2S, in concentrated form, is extremely corrosive to the steel pipes and containers used to transport the hydrogen sulfide-containing gases and liquids. As a result of all of the above-described problems, H2S-containing natural gas formations have tended to be underutilized in the petroleum industry. There is currently a great deal of renewed interest in using the world's plentiful natural gas resources. As a result, there is great effort in the industry now being directed toward separating at the well site the hydrocarbon portion of petroleum gases from its hydrogen sulfide component, and recovering the H2S as elemental sulfur. While various methods exist for removing hydrogen sulfide from gases and liquids during petroleum processing, most of those processes require large, expensive Claus plants, or modified Claus plants, for extracting and processing the sulfur. Conventional desulfurization operations are not practical for use at small operations such as remote well sites or on natural gas producing off shore oil platforms. A more economical, efficient method employing less equipment for the selective removal of hydrogen sulfide from natural gas at the site of production is needed.
Sulfur-recovery plants, also called Claus plants, are well known for use in removing sulfur from hydrogen sulfide gas resulting from petroleum refinery processes such as crude oil hydrodesulfurization processes. The Claus method is efficient for processing large quantities of gases containing a high concentration (i.e., >40 vol. %) H2S for plants producing more than 100,000 tons of sulfur per year. The Claus process is not suitable for use in cleaning up hydrogen or light hydrocarbon gases (such as natural gas) that contain H2S, however. Not only is the hydrocarbon content lost in the initial thermal combustion step of the Claus process, but carbon, carbonyl sulfide and carbon disulfide which are produced cause catalyst fouling and dark sulfur. Moreover, carbonyl sulfide is difficult to convert to elemental sulfur. Over the years various changes to the Claus process have been suggested, many of which are directed primarily toward improving or replacing the thermal reactor. See, for example, U.S. Pat. Nos. 4,279,882, 4,988,494, 5,597,546 and 5,653,953.
In the past, others have usually addressed the problem of purifying hydrogen sulfide contaminated hydrogen or gaseous light hydrocarbon resources by employing an amine extraction technique. Typically, alkanolamine absorption of the H2S component of the gas stream is performed, followed by H2S regeneration and conventional multistage Claus sulfur recovery, usually including tail gas treatments. According to conventional industrial practices, a hydrocarbon or hydrogen containing gas stream containing a low concentration of H2S is contacted with a water solution containing an alkanolamine. Alkanolamines commonly employed in the industry are monoethanolamine (MEA), diethanolamine (DEA), methyldiethanol amine (MDEA), diglycolamine (DGA), and diisopropanolamine (DIPA). These are basic nitrogen compounds. The basic alkanolamine reacts with the H2S and other gases that form acids when dissolved in water to form alkanolamine salts, according to the following generic reaction:Alkanolamine+Acid Gas=Protonated alkanolamine+weak acid anionWhen ethanolamine is the basic alkanolamine, the reaction is:H2N—CH2CH2OH+H2S→+NH3—CH2CH2OH+HS−  (1)
The hydrogen or hydrocarbon gas, substantially freed of H2S, is recovered and may be used as fuel or routed to another system for processing. After absorbing the H2S from the gas, the alkanolamine solution is transported, heated, and placed in a stripping tower. Steam, generated from boiling the alkanolamine solution at the bottom of the stripping tower, lowers the vapor pressure of the acid gas above the solution reversing the equilibrium of the acid gas/alkanolamine reaction shown above. The acid gases leaving the stripper are cooled to condense most of the remaining steam. The acid gas stream then goes to a Claus sulfur recovery plant. In the Claus sulfur plant, the H2S gas from the alkanolamine stripper is contacted with air or a mixture of oxygen and air in a flame. One third (⅓) of the H2S is burned according to the equation:H2S+ 3/2O2→SO2+H2O  (2)The remaining ⅔ of the H2S is converted to sulfur via the Claus reaction:2H2S+SO2⇄3/xSx+2H2O  (3)(x=2, 6, or 8 depending on temperature and pressure)
The gases are cooled in a fire tube boiler after the burner. Nominally, this step converts 55 to 70% of the H2S to elemental sulfur. The equilibrium of the Claus reaction of equation (3) limits the conversion. To improve the yield, elemental sulfur is condensed from the gas stream. After sulfur condensation and separation from the liquid sulfur, the unreacted gases are heated to the desired temperature, passed over a catalyst that promotes the Claus reaction, and cooled again to condense and separate the sulfur. Typically, 2 to 3 stages of Claus reheater, reactor, and condenser stages are employed. Anywhere from 90 to 98% of the H2S fed to the unit is recovered as elemental sulfur.
Any remaining H2S, SO2, sulfur, or other sulfur compounds in the Claus plant effluent are either incinerated to SO2 and discharged to the atmosphere, or incinerated to SO2 and absorbed by chemical reaction, or converted by hydrogen to H2S and recycled or absorbed by an alkanolamine solution. This is accomplished by various Claus “tail gas” treatment units, which improve the efficiency of sulfur removal from the gas discharged to the atmosphere. Other techniques for improving efficiency of sulfur removal that have been described in the literature include: 1) adsorbing sulfur cooled below the freezing point on a solid material followed by releasing the trapped sulfur as a liquid by heating the solid adsorbent; 2) selectively oxidizing the remaining H2S to sulfur using air; and 3) selectively oxidizing the H2S to sulfur employing aqueous redox chemistry utilizing chelated iron salts or nitrite salts in an attempt to purifying hydrogen sulfide contaminated hydrogen or gaseous light hydrocarbon resources. According to these methods, the H2S-contaminated hydrogen or hydrocarbon stream is contacted directly with the redox reagent such as chelated iron (III) ions. The iron (III) is reduced to iron (II) ion while the H2S is converted to elemental sulfur. The sulfur in liquid form is separated from the solution. These types of desulfurization units have been proven to be practical when the amount of sulfur to be removed from the stream is below 5 long tons per day.
U.S. Pat. Nos. 5,700,440; 5,807,410 and 5,897,850 describe some of the limitations of existing tail gas treatment (TGT) processes and the difficulty of meeting increasingly stringent government requirements for desulfurization efficiency in the industry. J. B. Hyne (Oil and Gas Journal Aug. 28, 1972: 64:78) gives an overview of available processes for effluent gas stream desulfurization and discusses economical and environmental considerations. R. H. Hass et al. (Hydrocarbon Processing May 1981:104-107) describe the BSR/Selectox™ process for conversion of residual sulfur in Claus tail gas or for pre-Claus treatment of a gas stream. K-T Li at al. (Ind. Eng. Chem. Res. 36:1480-1484 (1997)) describe the SuperClaus™ TGT system which uses vanadium antimonate catalysts to catalyze the selective oxidation of hydrogen sulfide to elemental sulfur. U.S. Pat. No. 5,603,913 describes several oxide catalysts that have been suggested for catalyzing the reactionH2S+½O2→½S2+H2O  (4)Because reaction (4) is not a thermodynamically reversible reaction, direct oxidation techniques offer potentially higher levels of conversion than is typically obtainable with thermal and catalytic oxidation of H2S. Most direct oxidation methods are applicable to sour gas streams containing relatively small amounts of H2S and large amounts of hydrocarbons, but are not particularly well suited for handling the more concentrated acid gas streams from refineries. For this reason direct oxidation methods have been generally limited to use as tail gas treatments only, and have not found general industrial applicability for first stage sulfur removal systems from gases containing large quantities of H2S. According to B. G. Goar (Hydrocarbon Processing 47:248-251 (1968)) the acid gas stream for the modified Claus process should contain less than 2 mole % of light hydrocarbons and from 15 to essentially 100% H2S.
This restriction to low H2S concentration gases is due, in part, to the increase in adiabatic heating of the catalyst bed that occurs at higher concentrations of H2S, i.e., above about 3 vol. %. The limit of heat tolerance of the reaction vessel, which is typically made of steel, can be quickly reached when a high concentration of H2S is reacted. Also, the higher temperatures (above about 350° C.) cause an increase in the rate of reaction of SO2 formation. Additionally, the H2S concentration range is usually kept low because of the necessity for supplying excess O2 to overcome deactivation of most direct oxidation catalysts caused by water. As a practical matter, this need for a stoichiometric excess of O2 precludes using H2S concentrations above about 2 vol. %. J. A. Lagas et al. (Oil & Gas Journal Oct. 10, 1988: 68-71) describe a selective-oxidation catalyst (SuperClaus™) for use in a third tail gas reactor to improve a Claus process. It is suggested that in an excess of air, an ideal catalyst should be insensitive to H2O concentration, incapable of oxidizing CO, H2 or CH4, incapable of forming COS and CS2, and active for producing only a very small amount of SO2. The composition of such ideal catalyst is not disclosed. S. W. Chun et al. (Applied Catalysis B: Environmental 16:235-243 (1998)) describe a TiO2/SiO2 particulate catalyst that is not deactivated by the water formed in the partial oxidation reaction at a reactant gas ratio of 0.5-4 O2:H2S. In that report the H2S conversion is carried out with a fixed bed catalyst at a temperature of 275° C. and at a gas hourly space velocity (GHSV) of 3000 hr−1.
Amine strippers and Claus plants in use today are normally operated at less than 2 atmospheres pressure. Because of this low pressure, the pipes and vessels have very large diameters for the flow compared to most refinery or gas plant processes. The low pressure operation forces the equipment to be designed for low pressure drop to have adequate capacity. Therefore, a typical modified Claus plant, together with one or more tail gas treatment units, is large and the plant includes a great deal of equipment.
There have been many efforts to reduce the size, cost or complexity of sulfur removal plants. For instance, U.S. Pat. No. 4,279,882 describes using a catalytic selective oxidation process to eliminate the conventional Claus combustion chamber and heat exchanger. According to that process, stoichiometric amounts of oxygen and H2S are passed over a vanadium oxide catalyst on a porous refractory oxide support. The catalyst is described as being substantially incapable of oxidizing hydrogen, methane and carbon monoxide and capable of selectively oxidizing H2S to SO2 and sulfur, without forming SO3. The upper limit of the reaction temperature is 850° F. (454° C.) in order to avoid damage to steel vessels and to prevent formation of tarry products from C3 or greater hydrocarbon components in the feed gas. At least one additional Claus catalytic reactor follows the first stage oxidation stage.
Z. R. Ismagilov et al. (React. Kinet. Catal. Lett. 55:489-499 (1995)) suggest that monolith catalysts containing oxides of Co, V, Fe, Cr, Mn or Al have activity for catalytically converting the H2S in natural gas to sulfur in a first oxidation stage. The reaction conditions include a spherical particulate vanadium catalyst in a fluid bed reactor operating at 250-300° C., O2:H2S=0.5-1.1 and tc=0.5-0.8 s. Under such conditions H2S conversion and process selectivity of 99% is reported.
U.S. Pat. No. 4,886,649 (Ismagilov, et al.) describes a two stage direct oxidation process employing fluidized catalyst beds containing MgCrO4 and Al2O3, or V2O5 and Al2O3. According to that method, oxygen is supplied to the first oxidation stage in an amount of 100-110% of the stoichiometric amount necessary for oxidation of H2S to elemental sulfur. The range of treatable H2S containing gases is extended to gases containing about 30-50 vol. % H2S. The granular catalyst in a fluidized bed with a cooling coil or jacket, allows temperature uniformity of the catalyst bed. A maximum temperature level of 250-350° C. is desired in order to avoid forming products of coking and cracking of hydrocarbon components of the feed gas.
U.S. Pat. No. 6,235,259 (Ledoux et al.) describes a regenerative process for oxidizing H2S contained in low concentration in a gas directly to sulfur over a Ni, Fe, Co, Cu, Ch, Mo or W oxysulfide catalyst carried on a silicon carbide support and a transition metal compound. The direct oxidation is carried out at a temperature that is below the dew point of the sulfur, which becomes deposited on the catalyst. Periodically, the catalyst is regenerated by flushing the sulfur-laden catalyst with a 200-500° C. non-oxidizing gas to vaporize the sulfur, and the catalyst is then cooled for reuse.
U.S. Pat. No. 6,299,851 (Li et al.) describes a method for selectively oxidizing hydrogen sulfide to elemental sulfur at a temperature of 50 to 400° C. and at a pressure of 0.1 to 50 atm in the presence of a catalyst. The catalyst includes a vanadium-containing material, which could be vanadium carbide, and a catalytic substance chosen from scandium (Sc), yttrium (Y), lanthanum (La), samarium (Sm) and compounds thereof.
In an unrelated area of endeavor, various carbided metal catalysts have been prepared, some of which have been used for catalyzing the oxidative conversion of methane to synthesis gas. For example, Claridge et al. (J. Catalysis 180:85-100 (1998)) have described high-surface-area molybdenum carbide catalysts and tungsten carbide catalysts for conversion of methane to synthesis gas via steam reforming, dry reforming or partial oxidation processes. Maintaining elevated pressure during the conversion process stabilized the carbide and deterred catalyst deactivation.
U.S. Pat. No. 4,325,843 (Slaugh et al.) describes a process for making a supported tungsten carbide composition for use as a catalyst. The process includes impregnating an oxidic support material with a solution of a tungsten salt, converting the tungsten to a nitride and treating the supported tungsten nitride with a carbiding gas mixture.
U.S. Pat. No. 4,325,842 (Slaugh et al.) describes a process for preparing a supported molybdenum carbide catalyst by impregnating a porous support with a solution of hexamolybdenum dodecachloride, drying, and heating in a carbiding atmosphere. U.S. Pat. No. 4,326,992 (Slaugh et al.) describes another process for preparing a supported molybdenum carbide catalyst. In this process an ammonium hydroxide solution of molybdic acid is applied to a porous support, dried and heated in a carbiding atmosphere. U.S. Pat. No. 5,338,716 (Triplett et al.) discloses a supported non-oxide metal carbide-containing catalyst that includes an oxide support, a passivating layer, and a non-oxide metal ceramic catalytic component such as tungsten carbide or molybdenum carbide, or another Group VI metal carbide or nitride.
U.S. Pat. Nos. 5,451,557 and 5,573,991 (Sherif) disclose other processes for forming a metal carbide catalyst such as tungsten carbide or another Group VIB transition metal carbide. U.S. Pat. No. 4,331,544 (Takaya et al.) describes a catalyst for catalyzing the synthesis of methane from CO and H2. That catalyst comprises a nickel-molybdenum alloy and a molybdenum carbide supported on a porous carrier. Still other metal carbide catalysts are disclosed in U.S. Pat. Nos. 4,219,445 (Finch), U.S. Pat. No. 1,930,716 (Jaeger), and U.S. Pat. No. 4,271,041 (Boudart et al.).
None of the existing H2S direct oxidation processes adequately address the typical reactor temperature limitations nor do they operate at sufficiently high flow rates to be sufficiently useful industrially. Neither do the conventional desulfurization processes provide adequately high levels of H2S conversion and selectivity for elemental sulfur product in a single-pass reaction when treating higher concentration H2S streams. Catalysts used in the conversion of sulfur compounds today typically suffer from deactivation due to sulfur deposits and/or metal sulfide formation that removes the active form of the catalyst. Conventional methods that require the handling of sulfur-containing hydrocarbon feeds typically use a high precious metal (e.g., Rh) loading. In the case of Claus-type processes, longer catalyst beds are used to offset the inevitable deactivation. A major drawback of conventional Claus processes is that the hydrogen used to form H2S in an upstream process is lost by forming water in the oxidation of the H2S. In a refinery where the hydrogen-generating processes do not keep pace with the rate of hydrogen consumption and hydrogen must therefore be externally supplied, sulfur recovery using the Claus process is particularly undesirable. Most existing desulfurization processes and systems must resort to use of additional pre-treatments or post-treatment catalytic stages and tail gas treatments in order to salvage the usable hydrocarbon constituents of the gas stream and to adequately clean the waste gas that is vented into the air. Better systems and processes for removing sulfur from H2S will find widespread use in a number of industrial applications, particularly in the petroleum industry for more effectively utilizing the world's abundant H2S-containing natural gas resources, much of which contains 3-40% H2S.